Asphaltene damage in matrix acidizing

Abstract

This work addresses the problem of asphaltene deposition that occurs during acid treatments of oil reservoirs. Asphaltenes are present to some degree in most hydrocarbons. Due to the molecular weight of the components these asphaltenes are more concentrated in crude oil than in gas. The asphaltene particles are present in the crude oil as dispersed colloids. During the life of a reservoir an event may occur that causes the destabilization of this colloidal dispersion. The destabilization can cause asphaltene deposition in the reservoir. Frequently, the cause of destabilization is the acid stimulation of the reservoir. Published work in the field of matrix acidizing has been limited to cores saturated with brine. Research in two phase systems has been limited by problems encountered when acidizing oil saturated cores. A core flow apparatus was constructed to solve these problems. Berea sandstone cores were vacuum saturated with brine and various oil samples to simulate a water wet reservoir. These core were acidized with three stage treatments of 15% hydrochloric acid (HCl), 12% HCL-3% hydrofluoric acid (HF) and 15% HCL. No additives were used in the acid. Comparisons were made between cores acidized with a variety of saturating fluids. Petrographic analysis was used to observe changes in the core. Migration of fines was documented with x-ray diffraction and thin section analysis. The HF and the mineral muscovite reacted at a rate that was much lower than expected. Pressure response data was used to locate and identify the damage mechanisms of asphaltenes. Damage was found to occur during the post treatment core flow of the crude oil.